Much of the electrical power used in homes and businesses throughout the world is produced in power plants that burn a fossil fuel (i.e. coal, oil, or gas) in a boiler. The resulting hot exhaust gas (also sometimes termed “flue gas”) turns a gas turbine or boils water to produce steam, which turns a steam turbine, and the turbine cooperates with a generator to produce electrical power. The flue gas stream is subsequently passed through an air preheater, such as a rotating wheel heat exchanger that transfers heat from the flue gas to an incoming air stream, which thereafter flows to the combustor. The partially cooled flue gas is directed from the air preheater to the exhaust stack.
The flue gas contains contaminants such as sulfur oxides (SOx), nitrogen oxide (NOx), carbon monoxide (CO) and particulates of soot when coal is used as the primary fuel source. The discharge of all of these contaminates into the atmosphere is subject to federal and local regulations, which greatly restrict the levels of these flue gas components.
To meet the reduced levels of NOx emissions from power stations, as required by environmental regulations, many fossil fuel-fired electric generating units are being equipped with either selective catalytic reduction (SCR) or selective non-catalytic reduction (SNCR) technologies. In SCR, the most common method used is to inject ammonia or urea based reagents in the presence of a vanadium oxide catalyst where the ammonia reacts to reduce the oxides of nitrogen. SCR is generally accomplished at lower temperatures than SNCR. The SCR system typically operates at flue gas temperatures ranging between 300° C. and 450° C. U.S. Pat. No. 5,104,629 illustrates one known type of SCR installation.
In SNCR, the most common method used is to inject ammonia or urea based reagents into the upper furnace to reduce the oxides of nitrogen without the use of a catalyst. The SNCR system operates at flue gas temperatures ranging between 850° C. and 1150° C. U.S. Pat. Nos. 3,900,554, 4,208,386, and 4,325,924 illustrate known types of SNCR applications.
At coal-fired power plants, ammonia injection systems for SCR and SNCR systems are typically installed in the high-temperature and high-dust region of the flue gas stream, which typically is prior to ash collection. One common problem with the SCR and SNCR technologies is that some residual ammonia, known as ammonia slip, negatively impacts downstream components and processes such as: air pre-heater fouling, fly ash contamination, and ammonia gas emission into the atmosphere. The ammonia slip problem is further exacerbated as the result of SCR catalyst surface deterioration as well as misdistribution in flue gas velocity, temperature, and concentrations of ammonia and NOx.
An additional problem with the current methods is that increased ammonia injections will more efficiently remove the oxides of nitrogen, but then the excess ammonia will result in increased ammonia slip in the flue gas. In coal-fired power plants this excess ammonia can, in addition, contaminate the resulting coal based fly ash.
Even in power plants that are based on natural gas or oil, the environmental effects of the exhausted ammonia is undesirable. The EPA has enacted a variety of regulatory initiatives aimed at reducing NOx. It was determined that the combustion of fossil fuels is the major source of NOx emissions. These control regulations were established by the EPA under Title IV of the Clean Air Act Amendments of 1990 (CAAA90). In July 1997 the EPA proposed another change in the New Source Performance Standards and these revisions were based on the performance that can be achieved by SCR technology.
As briefly described above, the treatment of exhaust gases from boilers and the like presents the following disadvantages:
(1) that some ammonia is left unremoved in the treated gas;
(2) low NOx decomposition rate; and
(3) large ammonia consumption.
The disadvantages (1) and (2) are correlated.
For example, if the ammonia supply is increased in order to raise the NOx decomposition rate, the proportion of residual ammonia in the treated gas will be high. This residual ammonia may exceed the amounts that are permitted by existing regulations to pass into the atmosphere. Thus, the nitrogen oxide separation efficiency of the known processes is limited by the amount of unreacted ammonia that can be discharged into the atmosphere.
Besides, variation in the load on the combustion equipment will change the temperature, at the point where ammonia is introduced, to a value deviated from the optimum temperature range, and this in turn will decrease the decomposition rate, tending to increase the proportion of residual ammonia. Even in a small proportion, the residual ammonia will react rapidly with the sulfuric acid content of the exhaust gas to produce acid ammonium sulfate. This product will stick to the rear heat-transfer surface in the relatively low-temperature region, for example, to the heating surfaces of the air preheater and associated parts of a boiler, causing an increase in pressure loss, hampering the operation of the combustion equipment, and attacking the materials of the equipment for their eventual corrosion.
As described above, the ammonia left unremoved in the treated exhaust gas provides a major obstacle in the way to practical operation. Consequently, there is an upper limit to the ammonia supply and naturally the NOx decomposition rate is low. This has been a problem in the practice of high-temperature noncatalytic denitrification. Furthermore, ammonia, which is introduced in the high-temperature region, undergoes a concomitant reaction for decomposing itself, resulting in the disadvantage (3) of excess consumption of ammonia, or more than the equivalent for the NOx-decomposing reaction. This tendency will be pronounced as the amount of ammonia injection is increased in anticipation of an enhanced decomposition rate. This has been another limiting factor for the rate of NOx decomposition to be attained conventionally.
It is important to accomplish the reaction of the ammonia and NOx in an efficient manner, for maximum possible reaction of both the NOx and the ammonia. If the reaction is incomplete, either NOx or ammonia (or both) may pass through to the stack and be emitted to the atmosphere. Both NOx and ammonia are classified as pollutants, and their emission is to be maintained within legal limits. Furthermore, depending upon the temperature at the cold end of the air preheater, excess ammonia slip may cause clogging of the space between adjacent air preheater heating elements because of the formation of ammonium sulfate/bisulfate, and/or agglomerated fly ash. This results in increased pressure loss of the heat exchanger, corrosion of the apparatus, and therefore unstable operation for a prolonged period and other disadvantages.
In addition, many coal-fired power plants dispose of the collected fly ash by selling it to purchasers who further process the fly ash for commercial uses (i.e. lightweight aggregate for concrete mixtures). Fly ash produced at coal-fired power plants is commonly used in concrete applications as a pozzolanic admixture and for partial replacement for cement. Fly ash consists of alumino-silicate glass that reacts under the high alkaline condition of concrete and mortar to form additional cementitious compounds. Fly ash is an essential component in high performance concrete. Fly ash contributes many beneficial characteristics to concrete including increased density and long-term strength, decreased permeability and improved durability to chemical attack. Also, fly ash improves the workability of fresh concrete.
When ammonia contaminated fly ash is used in Portland cement based mortar and concrete applications, the ammonium salts dissolve in water to form NH4+. Under the high pH (pH>12) condition created by cement alkali, ammonium cations (NH4+) are converted to dissolved ammonia gas (NH3). Ammonia gas evolves from the fresh mortar or concrete mix into the air exposing concrete workers. The rate of ammonia gas evolution depends on ammonia concentration, mixing intensity, exposed surface area, and ambient temperature. While it is believed that the ammonia that evolves has no measurable effect on concrete quality (strength, permeability, etc.), the ammonia gas can range from mildly unpleasant to a potential health hazard. The human nose detects ammonia odors at levels of 5 to 10 ppm. The OSHA threshold and permissible limits are set at 25 and 35 ppm for Time-Weighted Average (TWA) (8-hr) and Short-Term Exposure Limit (STEL) (15-min), respectively. Ammonia gas concentration between 150 and 200 ppm can create a general discomfort. At concentrations between 400 and 700 ppm, ammonia gas can cause pronounced irritation. At 500 ppm, ammonia gas is immediately dangerous to health. At 2,000 ppm, death can occur within minutes.
Other than OSHA exposure limits, there are no current regulatory, industry or ASTM standards or guidelines for acceptable levels of ammonia in fly ash. However, based on industry experience, fly ash with ammonia concentration at less than 100 mg/kg does not appear to produce a noticeable odor in Ready-Mix concrete. Depending on site and weather conditions, fly ash with ammonia concentration ranging between 100 and 200 mg/kg may result in unpleasant or unsafe concrete placement and finishing work environment. Fly ash with ammonia concentration exceeding 200 mg/kg would produce unacceptable odor when used in Ready-Mixed concrete applications.
In addition to the risk of human exposure to ammonia gas evolving from concrete produced using ammonia laden ash, the disposal of ammonia laden ash in landfills and ponds at coal burning power stations could also create potential risks to humans and the environment. Ammonium salt compounds in fly ash are extremely soluble. Upon contact with water, the ammonium salts leach into the water and could be carried to ground water and nearby rivers and streams causing potential environmental damage such as ground water contamination, fish kill and eutrophication. Ammonia gas could also evolve upon wetting of alkaline fly ashes, such as those generated from the combustion of western sub-bituminous coal. Water conditioning and wet disposal of alkaline fly ashes would expose power plant workers to ammonia gas.
U.S. Pat. No. 5,233,934 to Krigmont et al. discloses a control method of reducing NOx in flue gas streams utilizing an SNCR treatment followed by an SCR treatment. The Krigmont et al. method tries to maximize the NOx removal in the SNCR stage, subject to certain ammonia slip restrictions, and injecting additional ammonia for the SCR stage.
U.S. Pat. No. 5,510,092 to Mansour et al. discloses a combined SNCR/SCR process in which SCR is employed for primary NOx reduction and NH3 is injected into the SNCR zone only when the NOx content of the SCR effluent exceeds a pre-selected design maximum value.
The Minkara et al. patent application (U.S. 2003/0202927) discloses a process to reduce ammonia concentration and emissions from both coal-fired plants and plants that use other hydrocarbon fuels. The process in the Minkara et al. application adds an ammonia oxidation catalyst, specifically manganese dioxide, downstream of the SCR system to remove the undesirable ammonia slip by reacting the ammonia with the residual oxygen present in the flue gas.
As discussed above, for SCR of oxides of nitrogen with ammonia to work well and result in the lowest values of NOx, it is preferable to be able to use excess ammonia. However, when the quantity of ammonia used is high enough to effectively remove the NOx through SCR, some of the excess ammonia will go through the catalyst unchanged and exit as ammonia slip in the flue gases creating the problem of a toxic reactive gas in the exiting gases. Another major problem created by the excess ammonia exiting in the flue gases, particularly from coal-fired plants, is that the ammonia contaminates the fly ash that is intended for use in mixtures with cement to make concrete. Thus, a need exists for a safe and efficient method for minimizing ammonia slip downstream from the primary SCR catalyst.